WO2013025836A1 - Détermination de phase a/b/c à l'aide de compteurs intelligents d'électricité communs - Google Patents

Détermination de phase a/b/c à l'aide de compteurs intelligents d'électricité communs Download PDF

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Publication number
WO2013025836A1
WO2013025836A1 PCT/US2012/050994 US2012050994W WO2013025836A1 WO 2013025836 A1 WO2013025836 A1 WO 2013025836A1 US 2012050994 W US2012050994 W US 2012050994W WO 2013025836 A1 WO2013025836 A1 WO 2013025836A1
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WIPO (PCT)
Prior art keywords
power
phase
count
clock
meters
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PCT/US2012/050994
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English (en)
Inventor
Tyler J. Mckinley
Geoffrey B. Rhoads
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Digimarc Corporation
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Priority to US13/765,404 priority Critical patent/US9230429B2/en
Publication of WO2013025836A1 publication Critical patent/WO2013025836A1/fr
Priority to US14/987,134 priority patent/US9883259B2/en

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01R—MEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R29/00—Arrangements for measuring or indicating electric quantities not covered by groups G01R19/00 - G01R27/00
    • G01R29/18—Indicating phase sequence; Indicating synchronism
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D4/00—Tariff metering apparatus
    • G01D4/002—Remote reading of utility meters
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D2204/00—Indexing scheme relating to details of tariff-metering apparatus
    • G01D2204/40—Networks; Topology
    • G01D2204/47—Methods for determining the topology or arrangement of meters in a network
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02B—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO BUILDINGS, e.g. HOUSING, HOUSE APPLIANCES OR RELATED END-USER APPLICATIONS
    • Y02B90/00—Enabling technologies or technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y02B90/20—Smart grids as enabling technology in buildings sector
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E40/00—Technologies for an efficient electrical power generation, transmission or distribution
    • Y02E40/70—Smart grids as climate change mitigation technology in the energy generation sector
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S10/00—Systems supporting electrical power generation, transmission or distribution
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S10/00—Systems supporting electrical power generation, transmission or distribution
    • Y04S10/22—Flexible AC transmission systems [FACTS] or power factor or reactive power compensating or correcting units
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S20/00—Management or operation of end-user stationary applications or the last stages of power distribution; Controlling, monitoring or operating thereof
    • Y04S20/30—Smart metering, e.g. specially adapted for remote reading

Definitions

  • the present technology concerns smart grid systems, such as for electric power metering.
  • Smart Grid technologies offer utilities the opportunity to better generate, manage, control, distribute and secure energy. Energy usage across the globe is expected to rise 35% by 2030, driven by industrialization and economic growth. Given this curve and the need to upgrade national power grids to provide this power, the Smart Grid has international focus on how to use technology to better accomplish these goals.
  • a core tenet of the Smart Grid is the "Smart Meter.”
  • a smart meter is (typically) an electrical meter that records energy usage at a consumer's premise and communicates that data back to the utility for billing purposes and for monitoring. Smart meters are similar to the meters that have proliferated across households in the US for almost a century but include digital display and digital communications capabilities.
  • Advanced Meter Infrastructure is the term to describe a collection of smart meters in a service area, and the communication system that connects them to the utility. Because of these communication capabilities, smart meters offer tremendous value in other areas.
  • This space-time network provides asset tracking and management capabilities for the utility or other consumer of the location information.
  • the net effect of this capability is that each smart meter in a utility's service area becomes a "positioning satellite" and can provide location and positioning information for any device within the network.
  • T&D transmission and distribution
  • T&D transmission and distribution
  • AC Alternating current
  • AC power runs on a 60 Hz cycle which allows power to be transmitted and distributed across three phases: Phase A, Phase B and Phase C.
  • Each premise - whether it is a home or business - will be attached to a power line which is one of these three phases.
  • the problem is that there is no way to automatically determine the phase that any premise is attached to.
  • the AMI network made up of the Smart Meters in the utility's service area, can communicate from the premises all the way back up to the supervisory control and data acquisition (SCAD A) system. These Smart Meters have embedded capabilities that when leveraged can provide the timing synchronization required to provide the utility with the phase intelligence it needs.
  • the PhaseNet technology described patent 7,876,266, is an accurate and scalable timing synchronization method using wireless networks. Many times an accurate "absolute time" must be disseminated to devices across a large geographic area. Existing methods to do this are with GPS or accurate rubidium clocks, but they have difficulty distributing the required precision due to system, device, economic or environmental limitations.
  • PhaseNet can accurately synchronize the meter's time with the sub-station's absolute time to 5.5 milliseconds and better which is needed to determine the power phase.
  • a particular method is characterized by processing one or more clock-stamped messages received from one meter, together with zero crossing data generated by the other meter, to determine relative timing between zero crossings of power signals at the two meters.
  • the power at the first meter is determined to be in phase with, or leading or lagging by 120 degrees, the power at the second meter.
  • Clock-stamping can be by a free -running clock/counter in one of the meters, and indeed, may simply be a count from a counter that counts by increments up to a limit and then resumes counting at zero (e.g., a simple 8 bit or 16 bit counter).
  • Some embodiments offer much greater resolution, to well less than a degree of phase, enabling low cost meters to serve as a distributed network of phasor measurement units.
  • Fig. 1 is a block diagram depicting certain aspects of the present technology.
  • Figs. 2 and 3 are drawings from pending application 13/179,807, detailing how count- stamps in different devices establish relative timing.
  • Fig. 4 is a conceptual illustration of one particular embodiment of the present technology.
  • Fig. 5 shows a packet based network involving two devices, enabling their relative power phases to be determined.
  • Figs. 6A and 6B show how differential phase relationships can be resolved into absolute power line phases A, B or C.
  • Fig. 7 illustrates aspects of a data packet.
  • Fig. 8 is a diagram of a smart power meter than can be used in embodiments of the present technology.
  • Fig. 9 shows an arrangement by which an output from a free-running counter/clock is latched when a zero-crossing detector senses a zero-crossing.
  • Onboard a typical smart meter are two primary circuit boards: 1) a metrology board; and 2) a communications board. These communications boards each have their own clock and/or oscillators that can provide count-stamps, which are the raw timing and location information for the PhaseNet algorithms.
  • a network communication script is implemented, for example, from a sub-station.
  • the script looks very similar to the normal 'meter reading' scheduling already happening that routes usage data about the premises to the utility. For example, Sub-station A exchanges several duplex packets with meters B, C and D over a few tens of seconds of time; Meter B duplex exchanges several packets with E, F and G before, during, or after the A exchanges; Meter G duplex exchanges with H and I, same drill, before, during or after. This is consistent with the space-time network description embodied in previous filings by the applicant, mainly patent 7,876,266.
  • a chosen 'counter which is typically the oscillator or clock on the transceiver or metrology board, count-stamps incoming and outgoing packets.
  • the communication protocol can also be used as the count- stamping source, much like the Time Synchronization Function (TSF) in the Beacon Frame of a Wi-Fi network.
  • TSF Time Synchronization Function
  • Each nodes passes back its collected count-stamp data, eventually getting all data back to a participating node at the sub-station or other location. This is the collective 'Pung' data noted in patent 7,876,266.
  • the sub-station node (or “collection node”) sends all Pung data, including metadata indicating which node is the 'master node,' which knows what phase A, B or C it is on, to a PhaselD web service.
  • This web service is simply the raw PhaseNet processing that can be located in the cloud, a data center, locally, etc.
  • the web service calculates inter-counter relationships (i.e. ZuluTime), determines each node's effective count value relative to the master node, then assigns A, B or C to each node based on what phase it has relative to the master node's A, B or C (or all three).
  • Fig. 1 describes this chain, where the laptop is acting as both the sub- station node and the processing web service.
  • Figs. 2 and 3 are from the applicant's previous patent filing entitled Location Aware Intelligent Transportation Systems (pending application 13/179,807, filed July 11, 2011), and illustrate after many messages are sent between nodes in a group, one node's counter can be related to any other node's counter via these 'DZT functions,' which is Delta ZuluTime.
  • These are ways of saying "when node N has counter value 3245246830, node M will be having counter value 5662594625,” and so forth.
  • the graphic cases are for more complicated cars moving down a street. In the case of smart meters, distances will be fixed and the raw counter values from the smart meter chips will be coarser than in the intelligent transportation case, but they are still adequate to determine sub-millisecond error-bar relationships between meters.
  • PhaseNet relates some given meter in the field and its ZCD counter value to the master counter value at the sub-station.
  • Patent documents 7,876,266 and 20090213828 teach how counters and/or clocks on one device can relate their instantaneous values with a second device through the simple act of exchanging packets of communication between the two devices, 'count-stamping' those exchanged packets as they are sent out from one device and/or received by the other device (there are many options described therein, hence the 'and/or').
  • the present technology can involve smart meters as the communicating devices, adding the step where the smart meter also count-stamps the 60Hz phase (usually the positive or negative zero crossing) of the electrical supply line to it.
  • these collective count-stamps are shared and processed, determining the A, B or C status of a given meter, an important parameter that has inspired various higher cost prior art methods to accomplish the same task.
  • This technology lends itself toward a de facto lowest cost approach toward accomplishing this goal automatically, not requiring a human visit to any given meter.
  • One configuration posits a computer at some central station collecting area- wide information and thereby determining all the A, B and C phases of meters within its region.
  • a second configuration describes a web service, also known as generic cloud processing, where meters simply send their raw count-stamp data to an IP address, and a computer at that address processes the A, B and C determinations.
  • Fig. 4 depicts one of the aspects of the technology, whereby a counter or clock on a smart meter that measures the phase of electric power (in counts or in 'time') is also used to measure the sending and/or receiving of messages within a communications 'stack.' In smart meters where there are separate counters (or clocks) used to measure these separate items, an additional step of 'correlating the counters' is performed to get to the same end.
  • Fig. 5 details an illustrative chain of events whereby a smart meter communicates with either a second smart meter or some other device which has its own ability to measure power phase (A, B and C).
  • the core low level goal is to determine if two smart meters thus
  • the core approach is to use a shared message as an arbitrary but useful reference event such that otherwise non-coordinated counters can nevertheless formulate cross-measurements.
  • Figs. 6 A and 6B then show that once many smart meters are thus communicating and determining these differential power phase relationships, then all it takes is for one device in the entire group to 'know its phase, A, B or C - or, for a central power station to be in the group which definitively knows A, B or C - then the knowledge of A, B and C phase can propagate to all devices. In other words, chains of relative knowledge are established, and then these are resolved by introduction of one known datum.
  • one implementation of this technology employs a 'web service' with an IP address that acts as a coordinator for some given large group of devices (often including a central power station), minimizing the necessary data generation, packaging and processing steps for individual smart meters.
  • the web service can be a component of a utility's larger GIS -based asset management system.
  • a driving idea is to minimize a smart meter's operations to just generating the raw data from the power phase and the communication packets (the pings if you will, with the term 'ping' now being extended to count- stamping power phase zero crossings), then shipping the raw data to an IP address.
  • the meter's job is essentially then done. This should represent the de facto lowest cost approach to implementing this technology, or possibly any other approach to automatically measuring A, B and C phase of smart meters.
  • the web service can deliver phase data back to the customer meters, and/or to the central office.
  • a disconnection between the supplier of smart meters, and a service that assists in automatically determining the A, B and C phases of such meters, may be one of several approaches to dealing with this tension.
  • the technology is implemented in a fashion in which data generation at the smart meter is standardized, and is able to be shipped to some third party-run service, as opposed to being slaved to (monopolized by, critics might charge) some proprietary service.
  • newer smart meters are integrated into the grid over time, they can leverage communication from un-cooperating meters that simply report measurements, but may not reliably provide packet count stamping.
  • a common event scenario is a storm that brings down power lines throughout a service area.
  • utilities call on service personnel from other utilities - sometimes from other states - to try and restore power as soon as possible.
  • visiting lineman crews that are working amidst a storm to restore power to dark neighborhoods aren't likely to be concerned about load balancing among the utility's A, B and C phases. If a line has power, they'll connect to it.
  • the utility can poll the meters to determine relative power consumption on the A, B and C phases. This determination can be made based on many hierarchies of geography - within a neighborhood, within a substation's service area, etc.
  • balance (1/3 - 1/3 - 1/3) is achieved at each level. Imbalances can be corrected in a more leisurely period after the storm, by dispatching crews to switch certain customers to certain phases, as needed.
  • Load balancing is not only a concern to utilities in managing efficient power distribution across a power grid.
  • Industrial consumers also have substantial economic interest in receiving balanced three-phase power supply.
  • Industrial sites typically employ three phase power to operate expensive capital equipment, such as industrial generators. When the three phases are of the power supplied to such equipment is even somewhat out of balance, such as 30%, 35%, 35%, the useful life of this equipment has been shown to be significantly reduced.
  • Such a charge-as-required model for determining meter phase helps placate profit- wariness within a highly scrutinized market, yet allows for companies to commercially operate.
  • This model is also generally preferable to vendors of smart meters, since it does not burden such costs onto the upfront meter cost.
  • patent documents 7,876,266 and 20090213828 describe in great detail how local counters and/or clocks on devices can latch instantaneous datum upon either the sending or receiving of RF-domain communication packets.
  • An example of such a communications- equipped meter is the Silver Springs NIC 300 family of products. To the extent current and future smart meters utilize packet-based communications, these same approaches to count- stamping data communications can be used in this technology.
  • Example use of 'clocks' might be as simple as generic software calls for 'time of day' or TOD when one is integrating several individual integrated circuits to make up a fully packaged 'smart meter.'
  • An aspect of certain embodiments of this technology is to correlate electrical power phase events (often referred to as zero-crossing data or ZCD) to these communications events (transmits and receives of communication data packets, a.k.a. 'pings' in the referenced patents).
  • ZCD zero-crossing data
  • An example is where a given counter on a first device is running at roughly one million counts per second. 'Roughly' is used in deference to typical 'PPM' or parts per million deviations of actual counters/clocks about some perfect number of counts per second (as if calibrated by an atomic clock).
  • An incoming message packet might be recorded at some number, say 123000000.
  • some ZCD event on the electrical power waveform may be recorded at some other moment, say 123456789. This ZCD event was thus 456,789 counts different than the receipt of some arbitrary communications packet. This would be 'roughly' 0.457 seconds later. For determining A, B and C phases, one will find that many of these 'roughly' kind of situations are just fine.
  • This correlation of a single (and random) incoming message event with a ZCD doesn't reveal much on its own. But this information can be compared to what a sending device (also with a 'roughly' 1 million count per second counter) may have done prior to sending that message to our first device. We can imagine that this second device recorded a 987000000 count on one of its ZCDs, then recorded that it sent out the message packet at counter value
  • device 2's ZCD was 544,000 counts off from when it sent out the message packet.
  • phase measurement Those practiced in the art of A, B and C phase measurement know that, for example, all meters on phase A will have ZCD's roughly in synchrony every 16.6 milliseconds, or 0.0166 seconds. This is the reciprocal of 60 Hz. If another meter is on phase B or C, there will be a 5.55 millisecond lead or lag from this 16.6 ms synchrony. In our example above, 1.001 second is very close to the predicted 1.000 seconds that would occur assuming device 1 and 2 are on the same phase.
  • ModDelay 60* Mod(Delay, 1/60); where Mod is the modulo operation;
  • A:A or B:B or C:C for ModDelay-0.000 device 1 relative to device 2 power phase A:C or B:A or C:B for ModDelay ⁇ 0.333
  • device 1 relative to device 2 power phase is for one of the devices to be at a central station and thereby simply 'know' what phase it is on, then it can look to the above guide to determine the other device.
  • the threshold for ambiguous cases can be a utility- set parameter. Typically, two or three standard deviations may be a suitable range. Any ModDelay outside that range is further analyzed by reference to timings involving one or more other devices. These errors can also be dealt with using various filtering, modeling, averaging, and least squares estimation error minimization functions. Kalman decomposition is another approach to addressing such error phenomena.
  • the device may instead may be configured to transmit its clock-stamped packet immediately after it detects a zero crossing. While receipt of this message by the first device isn't exactly synchronous with the detected zero crossing at the second device, the delay may be short enough to be disregarded - further simplifying the math.
  • a single transmit/receive event of a single message serves as a temporary and arbitrary shared reference between two devices, allowing them to derive modulo phase measurements.
  • Receive-only approaches also exist where the first device can also send a message to the second device for a duplex coordination of internal counter values based solely on received pings.
  • Web services like that conceived for the present technology have application in other areas as well.
  • the PhaseNet technology detailed in the cited patent documents can be implemented in a web services model for location determination.
  • Individual nodes report elemental data to a central server, which processes the received data to identify the location of each node.
  • a driving idea is to minimize the functional requirements of what exactly a smart meter needs to do in order to enable this technology, keeping its task to just generating, packaging and shipping data to an IP address. Previous discussions have gone in the 'generating' part of that statement.
  • the collected data is packaged into some standardized format for delivery to a smart-meter dedicated web service that determines A, B and C phases for a very large number of client devices.
  • the transmission of this data would utilize the standard communications that the gives the smart meter the first part of its name: 'smart.' Typical amounts of data to be transmitted are in the few kilobyte range at most, except where there is a great deal of noise/error in the system and larger amounts of data may be necessary.
  • An exemplary packet body format (i.e., not including header information - such as address data, framing data, error correction data, etc.) is shown in Fig. 7. Included are fields for data specifying the identity of the sending device, the location of the sending device (optional), and the measurement data being relayed (e.g., count-stamp information). Also included are security data (e.g., specifying the use to which the packet data can be put - such as a reference to applicable privacy rules), and other network and administrative data (e.g., battery state). In some implementations, the packet is encrypted. (Some packet formats can represent data in plural different manners, to accommodate customizations or extensions by different equipment suppliers.)
  • a similar packet arrangement can be employed for data sent to the power meters.
  • the contents of these fields can be data, or they can be links (e.g., URLs or other pointers) to data that is stored elsewhere and accessible to the receiving station.
  • links e.g., URLs or other pointers
  • Fig. 8 is a diagram of a representative smart power meter. This diagram is based on a reference design published by Texas Instruments (c.f., Smart Grid Solutions, Texas Instruments, 2012), using various system-on-a-chip components. Included are the MSP430F673x single phase electricity metering (metrology) chip, the Stellaris 9000 series ARM Cortex M3 microcontroller, the TMS320F28xx power line communication chip, and the CC430F6135 (or CC430F6137) microcontroller with integrated radio transceiver (communications) chip. Texas Instruments publishes extensive literature to guide the artisan in the use of such components.
  • the data channel 72 is not part of the TI smart meter reference design in Fig. 7.
  • This link is provided in some embodiments to enable zero crossings detected by the metrology system to be count-stamped by reference to the same clock that count-stamps packets sent/received by the communications system (or vice versa). While not essential, the use of a common count-stamp for all such events offers a bit of simplification. (Indeed, if the relationship between the zero crossing count and the time reference of the packet sender are known, it is sufficient to share zero crossings and monitor the relationship of zero crossings between meters. Errors introduced by such variations in packet transmit times can be averaged out, modeled and removed, etc., as noted in other discussions about dealing with errors.)
  • zero crossings can be count-stamped by reference to a clock in the metrology unit, and packets can be count- stamped by reference to a different clock in the communications unit.
  • count-stamp data generated in the metrology and/or communication units is buffered in memory provided in that unit, available for read-out when called for (such as in an asynchronous mode, where relative timing is derived by also tracking packet send or receive counts).
  • the count stamped zero crossing are measured with a time base that is synchronous with message transmission (i.e., two separate count stamps, one for zero crossing and one for message sending, are not always required).
  • Fig. 9 shows an arrangement including a power line, a zero-crossing detector, a free- running counter, and a latch circuit, a packet formatter, and a wireless transmitter.
  • the zero-crossing detector senses a zero-crossing, it produces an output signal. This signal triggers the latch circuit, causing it to capture and store whatever value the counter output at that instant.
  • the latched count output is provided to the packet formatter for inclusion in a data packet.
  • This packet is transmitted by the LAN, e.g., to another device (e.g., power meter) or web service.
  • the counter and latch circuit of Fig. 9 can be in the metrology unit, but needn't be so.
  • the output from the zero-crossing detector can be communicated to a counter unit elsewhere in the system (e.g., in the WAN).
  • the link between the latch and the packet formatter needn't be direct.
  • the latched value can be communicated across a system bus.
  • a phasor measurement unit (PMU) or synchrophasor is a device which measures the electrical waves on an electricity grid, using a common time source for synchronization. Time synchronization allows synchronized real-time measurements of multiple remote measurement points on the grid. In power engineering, these are also commonly referred to as synchrophasors and are considered one of the most important measuring devices in the future of power systems.
  • a PMU can be a dedicated device, or the PMU function can be incorporated into a protective relay or other device.
  • a phasor is a complex number that represents both the magnitude and phase angle of the sine waves found in electricity. Phasor measurements that occur at the same time are called “synchrophasors," as are the PMU devices that allow their measurement. In typical applications phasor measurement units are sampled from widely dispersed locations in the power system network and synchronized from the common time source of a global positioning system (GPS) radio clock. Synchrophasor technology provides a tool for system operators and planners to measure the state of the electrical system and manage power quality. Synchrophasors measure voltages and currents at diverse locations on a power grid and can output accurately clock- stamped voltage and current phasors. Because these phasors are truly synchronized,
  • the technology has the potential to change the economics of power delivery by allowing increased power flow over existing lines. Synchrophasor data could be used to allow power flow up to a line's dynamic limit instead of to its worst-case limit.
  • a phasor network consists of phasor measurement units (PMUs) dispersed throughout the electricity system, Phasor Data Concentrators (PDC) to collect the information and a Supervisory Control And Data Acquisition (SCAD A) system at the central control facility.
  • PMUs phasor measurement units
  • PDC Phasor Data Concentrators
  • SCAD A Supervisory Control And Data Acquisition
  • WAMS Wide Area Measurement Systems
  • GPS time stamping can provide a theoretical accuracy of synchronization better than 1 microsecond.
  • Locks need to be accurate to + 500 nanoseconds to provide the one microsecond time standard needed by each device performing synchrophasor measurement.
  • PMUs must deliver between 10 and 30 synchronous reports per second depending on the application.
  • the PDC correlates the data, and controls and monitors the PMUs (from a dozen up to 60).
  • the SCADA system presents system wide data on all generators and substations in the system every 2 to 10 seconds.
  • PMUs often use phone lines to connect to PDC, which then send data to the SCADA or Wide Area Measurement System (WAMS) server.
  • WAMS Wide Area Measurement System
  • BPA Bonneville Power Administration
  • the FNET project operated by Virginia Tech and the University of Tennessee utilizes a network of approximately 80 low-cost, high-precision Frequency Disturbance Recorders to collect syncrophasor data from the U.S. power grid.
  • WAMS Wide Area Monitoring Systems
  • NASPI North American Synchrophasor Initiative
  • EIPP Eastern Interconnect Phasor Project
  • TVA Tennessee Valley Authority
  • This data concentration system is now an open source project known as the openPDC.
  • the DOE has sponsored several related research projects, including GridStat at
  • Load shedding and other load control techniques such as demand response mechanisms to manage a power system, (i.e. Directing power where it is needed in real-time) 3. Increase the reliability of the power grid by detecting faults early, allowing for isolation of operative system, and the prevention of power outages.
  • IEEE 1344 The IEEE 1344 standard for synchrophasors was completed in 1995, and reaffirmed in 2001. In 2005, it was replaced by IEEE C37.118-2005, which was a complete revision and dealt with issues concerning use of PMUs in electric power systems.
  • the specification describes standards for measurement, the method of quantifying the measurements, testing and
  • OPC-DA / OPC-HDA - A Microsoft Windows based interface protocol that is currently being generalized to use XML and run on non Windows computers.
  • IEC 61850 a standard for electrical substation automation
  • BPA PDCStream - a variant of IEEE 1344 used by the Bonneville Power Administration (BPA) PDCs and user interface software. From A, B, C Phase Determination to Phasor Measurement Units (Synchrophasors)
  • the sub- millisecond accuracy requirement of A, B C determination can move down toward microsecond and sub-microsecond level accuracies necessary for high quality PMU implementations.
  • the primary task at hand is to 'correlate' a) the time-stamping and/or count- stamping of the power phase inside a metrology unit, to b) the sending and/or receiving of communications packets by a wireless unit inside a smart meter.
  • these separate units are generally connected by a logical bus not inclined toward nor designed for precise correlation of these separate events (power phase, and packet transmission/reception). Beyond 2102, they need to be better correlated in order to reach the full potential of PMU performance and the sub- microsecond UTC calibration which is inherently possible.
  • One simple approach to ensuring this correlation is to create a pulsing circuit inside the metrology unit such that the wireless unit can directly sense a ZCD pulse using its own counter. This does not lend itself well to 'retrofitting' currently shipping smart meters, however.
  • a separate approach which does lend itself to retrofitting current commercially available smart meters is to collect a large but nor enormous set of count-stamp/time-stamp data from the metrology unit on the power phase, and to likewise send a large set of pulsing signals over the logical bus connecting a metrology unit indirectly with the wireless unit, then have the wireless unit count-stamp/time-stamp such a large set of bus signals.
  • the numbers of events here may range into the hundreds or thousands to enable standard averaging techniques for honing in on the critical correlation between the mechanism that latches data for power phase with the mechanism which latches data for the packet communications.
  • a single master clock (oscillator) serving an entire smart meter can also form the basis for this need for correlating power phase with communication packets.
  • the sub-microsecond recommendations for high quality PMU measurements should dictate design choices.
  • 20090213828 already have explained how nanosecond-scale correlations can be achieved in and between member devices of a communicating network; the engineering task here is to extend at least sub-microsecond-scale accuracies and precision to the 2012-era disconnected operations of measuring power phase and measuring timing of packet transmission/receipt.
  • the hallowed 1 microsecond (arbitrary 'guideline' for PMU performance supported by numerous studies and well within the capabilities of well-executed distributed GPS approaches) can easily be achieved across an entire metropolitan area. More classic (read: existing dedicated and more expensive PMUs of today) can then cross-correlate one metropolitan region to others.
  • More classic read: existing dedicated and more expensive PMUs of today
  • the upshot is that the prospect for a detailed understanding of the instantaneous phasor relationship between some random household in Sheboygan with some equally random household in Chula Vista becomes possible with this technology.
  • meter-level positioning of each and every smart meter will assist in removing 'known delay' characteristics, as inevitably 1 microsecond target system specifications drive down to 100 nanoseconds and then probably further down.
  • region-based anomaly detection as well as phase-maintenance algorithms can then be applied for those two opposite cases (tracking down anomalies as they are about to occur or have occurred, versus regulating a network in ways that keep anomalies at bay in the first place).
  • 'graphics' are not simply for human visual monitoring, they can form a GIS-like basis, both geographic and 'network-view,' for advanced control and analysis.
  • wireless communications are used between nodes in the detailed embodiments, other embodiments can use power line communications techniques.
  • GPS signals are not available in some locations, e.g., indoors, where meters may be placed.
  • Timing accuracy is commonly required, i.e., below 46 microseconds. More typically, measurements with still more timing accuracy are desired, e.g., below 10, 3, 1, 0.3 or even 0.1 microseconds (which corresponds to clock counters operating at 100 KHz - 10 MHz).
  • one particular arrangement employs a free running oscillator that drives a counter circuit.
  • the output of the counter circuit is captured, or "latched,” on the occurrence of a triggering event (e.g., a zero crossing, transmission of a packet, receipt of a packet, etc.).
  • a triggering event e.g., a zero crossing, transmission of a packet, receipt of a packet, etc.
  • Another particular arrangement employs "time of day" data that is commonly available in smart meters.
  • smart meters each can participate on relatively similar basis in terms of sharing zero crossing measurements and count- stamping function, with each smart meter capable of serving as at least a temporary master or server of phase indication or calibration to other nodes.
  • the server may act as a centralized receiver for zero crossing measurements.
  • client -router - server modes a router is added to a client server mode to facilitate the routing of packets to a server, and where appropriate, provide count stamping and circulating of packets among other nodes.
  • time-stamping of an event associates a time-related datum with the event.
  • This is typically a conventional time standard, such as GPS, UTC or Unix time, coordinated with a reference of some sort - commonly measured in seconds and related increments.
  • Count-stamping is a different term, and associates an event with a datum that commonly has no meaning outside the context of the particular counter/crystal oscillator/etc. from which it was derived.
  • some embodiments may simply share zero crossing measurements, with a count stamp on receipt only. Some embodiments may further just share zero crossing data, with the assumption that the time delay for putting the measurement in a packet and sending it and receiving it gets worked out in the sharing of packets over time. If the zero crossing measurement on one device is sufficiently accurate, and there is a fairly predictable delay in sending the zero crossing to a receiver, then count stamping on receipt can suffice. In some such arrangements, the zero crossing measurement on one device is one clock latch, and then the receipt of the measurement is another clock latch that is sufficient to inter-relate the time of one meter with the time of another meter.
  • the system need not count stamp the message, or in the reverse, the system can count stamp the message but not the zero crossing. If desired, such error is addressed through averaging or filtering or linear regression or modeling, or least squares estimation etc. of timing relationships based on tracking shared data over time. Kalman decomposition techniques can similarly be applied.
  • Radio communication can be by WiFi, Zigbee, WiMax, 4G, etc.
  • Such communication can be either direct (end point to end point), or in a packet- switched arrangement, relayed through one or more intermediate nodes (which can comprise smart meters).
  • PhaseNet technology e.g., as detailed in patent documents 7,876,266 and 20090213828
  • pings count-stamped transmissions
  • GPS GPS
  • the web service receives count- stamp data from a variety of nodes - including the intended meter, allowing the web service to determine the location of the meter and report this
  • Such a web service can periodically poll all meters and other distribution apparatus in a utility's service area, and update a central GIS (geographic information system) database with precise latitude/longitude coordinates for each device.
  • GIS Geographic information system
  • this same collection of count-stamped "ping" data from an ad hoc collection of network nodes can similarly be processed to derive a highly accurate network time - despite being based on individual clocks operating at different rates and with unknown timing errors.
  • Any device in the network e.g., a meter
  • having access to such a collection of count-stamped data can derive this network time standard (which, again, is more precise than the data commercially available from GPS).
  • PhaseNet thus offers the capability to synchronize meters without the added cost of adding dedicated GPS chips or other special purpose hardware dedicated to clock
  • the web services noted in this disclosure can be located in the cloud, a data center, a network router, locally (e.g., within a smart meter), etc.
  • the web service can calculate inter-counter relationships (i.e. ZuluTime, including clock rate relationships and clock offsets, etc.).
  • each includes one or more processors (e.g., of an Intel, AMD or ARM variety), one or more memories (e.g. RAM), storage (e.g., a disk or flash memory), a user interface (which may include, e.g., a TFT LCD and, for the web server, a keyboard, etc.), interconnections between these elements (e.g., buses), and an interface for communicating with other devices (which may be wireless, such as GSM, CDMA, 4G, W-CDMA, CDMA2000, TDMA, EV-DO, HSDPA, WiFi, WiMax, mesh networks, Zigbee and other 802.15 arrangements, or Bluetooth, and/or wired, such as through an Ethernet local area network, a T-l internet connection, etc.).
  • processors e.g., of an Intel, AMD or ARM variety
  • memories e.g. RAM
  • storage e.g., a disk or flash memory
  • a user interface which may include, e.g., a TFT
  • microcontrollers digital signal processors, etc. These instructions can be implemented as software, firmware, etc. These instructions can also be implemented to various forms of processor circuitry, including programmable logic devices, FPGAs, and application specific circuits - including digital, analog and mixed analog/digital circuitry. Execution of the instructions can be distributed among processors and/or made parallel across processors within a device or across a network of devices (including "the cloud”).
  • Devices according to the present technology can include software modules for performing the different functions and acts. Certain of the detailed devices may include operating system software that provides interfaces to hardware resources and general purpose functions, and also includes application software which can be selectively invoked to perform particular routines. Existing smart meter software and web services software can be adapted for many of the uses detailed herein.
  • APIs are provided to fetch values (e.g., count-stamps associated with packet and zero crossing events).
  • Software and hardware configuration data/instructions are commonly stored as instructions in one or more data structures conveyed by tangible media, such as magnetic or optical discs, memory cards, ROM, etc., which may be accessed across a network.
  • Certain devices may be implemented as embedded systems - a special purpose computer system in which the operating system software and the application software is indistinguishable to the user.
  • the functionality detailed in this specification can be implemented in operating system software, application software and/or as embedded system software.

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  • Physics & Mathematics (AREA)
  • General Physics & Mathematics (AREA)
  • Remote Monitoring And Control Of Power-Distribution Networks (AREA)

Abstract

Selon l'invention, des unités de mesure de phaseur (PMU) tendent à être spécialisées et coûteuses - reléguées uniquement à des points clés dans des réseaux de distribution d'énergie, et sont généralement dépendantes d'une technologie GPS. La présente invention détaille comment tout compteur intelligent - utilisant une communication sans fil - peut effectuer des mesures de synchrophaseur de qualité sub-microseconde. D'autres aspects concernent une détermination se fondant sur un compteur intelligent d'une phase A, B ou C du réseau d'énergie d'électricité triphasé. Ceci peut entraîner des paquets de messages autorisant un timbre de comptage envoyés à un compteur intelligent et/ou par celui-ci, puis l'association de tels timbres de comptage à des mesures locales de phase d'énergie par une unité de métrologie. Une fois qu'un réseau de tels compteurs intelligents activés et d'autres dispositifs est formé, un standard de temps de synchronisation à l'échelle métropolitaine et à l'échelle de la région entière sub-microseconde peut étalonner des mesures locales de phase d'énergie, où une simple détermination de phase A, B et C est une application facile d'une telle mesure. Une surveillance d'agrégation à bas coût de synchrophaseurs à l'échelle métropolitaine promet un prochain chapitre d'importance pour cette technique relativement récente.
PCT/US2012/050994 2011-08-15 2012-08-15 Détermination de phase a/b/c à l'aide de compteurs intelligents d'électricité communs WO2013025836A1 (fr)

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CN108535553A (zh) * 2018-06-25 2018-09-14 海南电网有限责任公司信息通信分公司 基于gis的电网停电可视化装置
DE102022129592A1 (de) 2022-11-09 2024-05-16 Sma Solar Technology Ag Vorrichtung und verfahren zur identifikation einer zuordnung von phasenanschlüssen zweier elektrischer geräte
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CN108535553A (zh) * 2018-06-25 2018-09-14 海南电网有限责任公司信息通信分公司 基于gis的电网停电可视化装置
CN108535553B (zh) * 2018-06-25 2024-05-31 海南电网有限责任公司信息通信分公司 基于gis的电网停电可视化装置
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